The presence of water in production fluids may cause problems while transporting hydrocarbons due to the formation of emulsions, clathrate hydrates, and wax deposits. The viscosity of water-in-oil emulsions makes transport through long distance pipelines difficult throughout the field life, especially as the watercut increases, which may require the use of pumps, larger pipe diameters, and/or multiple pipes to provide the backpressure necessary to cause or permit fluids to flow to the destination. Further, hydrates may form, for example, at the high pressures and low temperatures that may be found in pipelines and other hydrocarbon equipment. After forming, the hydrates can agglomerate, leading to plugging or fouling of the equipment. Often under the same conditions that cause hydrate formation, wax precipitation can occur, fouling lines and decreasing flow by effectively decreasing the pipeline diameter over time.
Clathrate hydrates (hereinafter hydrate) are weak composites formed from a water matrix and a guest molecule, such as methane or carbon dioxide, among others. Hydrates may form, for example, at the high pressures and low temperatures that may be found in pipelines and other hydrocarbon equipment. For any particular hydrate composition involving water and guest molecules, such as methane, ethane, propane, carbon dioxide, and hydrogen sulfide, at a particular pressure there is a specific hydrate equilibrium temperature, above which hydrates are not stable and below which they are stable. After forming, the hydrates can agglomerate, leading to plugging or fouling of the equipment or pipelines.
Various techniques have been used to lower the ability for hydrates to form or cause plugging or fouling. For example, such techniques have included the insulation of lines, active heating, dehydration of the hydrocarbon, and the adding of thermodynamic hydrate inhibitors (THIs), kinetic hydrate inhibitors (KHIs), and/or anti-agglomerates (AAs).
Insulation, active heating, and dehydration can be expensive, especially for subsea systems. Even with insulation, cool-down of production fluids can limit the distance of a producing pipeline. If a hydrate blockage does occur, insulation can be detrimental by preventing heat transfer from the surroundings that may be used for hydrate melting.
Thermodynamic hydrate inhibitors, such as methanol, monoethylene glycol, diethylene glycol, triethylene glycol, and potassium formate, among others, lower the hydrate formation temperature, which may inhibit the formation of the hydrate under the conditions found in a particular process. Thermodynamic inhibitors can be very effective at hydrate prevention, but the quantities required for total inhibition are large and proportional to the amount of water produced, leading to increasing and even prohibitive quantities late in field life. Low dosage hydrate inhibitors (LDHIs) exist, including kinetic hydrate inhibitors (KHIs) and anti-agglomeration agents (AAs). Kills delay the nucleation of hydrates, but not by changing the thermodynamic conditions. Instead, KHIs inhibit the nucleation and growth of the hydrate crystals.
An alternative to the use of THIs and KHIs is cold flow technology, in which hydrate can be formed in a manner that prevents hydrate particles from sticking to each other without the use of chemical inhibitors. For example, U.S. Pat. No. 6,703,354 to Waycuilis, et al., discloses a transport process for a wet gas that employs a subsea heat exchanger that uses the ambient subsea temperature to cool a hydrocarbon stream. A portion of the hydrocarbon stream is converted by the cooling to solid gas hydrate particles. A solid particle medium entrained within the hydrocarbon stream prevents the build-up of gas hydrate particles in the hydrocarbon flow. The gas hydrate particles mix with the remaining liquid phase components of the hydrocarbon stream to form a gas hydrate slurry, which is conveyed through a subsea transport pipeline.
Cold flow has been demonstrated to be successful in systems where oil is the external phase in a water-oil system. The external oil phase is important to this process since cold flow benefits from the generation of small water droplets that can be converted to hydrate particles. Following hydrate formation sufficient liquid should be present to mobilize the hydrate particles. However, at high watercuts, current cold flow strategies may be inadequate.
At high watercuts, where the water phase is external, uninhibited hydrate will continue to form until the water or the gas is exhausted, which may lead to plugging. Wax in another issue in long distance transport. Traditional methods for dealing with wax include insulation to prevent the fluids from dropping below the wax appearance temperature (WAT), pipeline pigging, wax inhibitors to slow deposition, and pour point depressants to prevent gelling. Like that for maintaining the temperature above the hydrate region, insulation may not be adequate in severe environments and will have limitations on the distance in which temperatures can be maintained above the desired WAT. In long distance transport, pigging also becomes more difficult due to the large amounts of fluid and wax to be pushed through the system, potentially resulting in a wax plug. The pressures required to push a pig through the system and move such fluids/wax could even require pumps, resulting in large capital costs. In addition, pigging could require long downtimes in extended pipes. Similar techniques to those used for hydrate inhibition may also be used to inhibit the formation of wax deposits.
These techniques discussed above may fall to keep hydrates and wax particles suspended throughout the entire transportation line to the surface, especially as the material passes through various temperature gradients. Further, as a field matures, it will produce more water. A field may eventually produce primarily water which can limit hydrate remediation strategies and can dictate the end of profitable field production.